EP Energy Announces Fourth Quarter and Full Year 2015 Results and Proved Reserves, and Provides 2016 Outlook Focused On Capital Efficiency and Financial Discipline

Feb 18, 2016, 16:15 ET from EP Energy Corporation

HOUSTON, Feb. 18, 2016 /PRNewswire/ -- EP Energy Corporation (NYSE: EPE) today reported fourth quarter and year-end 2015 financial and operational results for the company.

Key highlights include:

2015 Full Year Results

  • Annual production of 109.7 thousand barrels of oil equivalent per day (MBoe/d), including 60.5 thousand barrels per day (MBbls/d) of oil — a 10 percent increase in oil production from 2014
  • Adjusted earnings before interest and debt expense, income taxes, depreciation, depletion and amortization and exploration expense (Adjusted EBITDAX) of $1,641 million — a 6 percent increase from 2014
  • Total Adjusted Cash Operating Costs of $9.89 per barrel of oil equivalent (Boe), including lease operating expense of $4.64 per Boe — a 25 percent reduction in adjusted cash operating costs from 2014
  • $0.78 adjusted earnings per share (Adjusted EPS)
  • $5.46 Discretionary Cash Flow Per Share
  • 188 completed wells — in-line with company estimates
  • $942 million from settlements on financial derivatives
  • Non-cash impairment charge of approximately $4.3 billion

  2015 Proved Reserves and Future Drilling Inventory

  • Proved reserves of 546.0 million barrels of oil equivalent (MMBoe)
  • 55 percent oil and 71 percent liquids
  • Pre-tax present value of proved reserves discounted at 10 percent (PV-10) was $2 billion based on 12/31/15 SEC pricing1, excluding approximately $800 million of hedge mark-to market (MTM) value
  • Added 197 future locations to drilling inventory through Eagle Ford acquisition and now have 5,709 identified drilling locations

2016 Outlook

  • $500 million to $900 million oil and gas expenditures
  • 91 MBoe/d to 97 MBoe/d total production
  • 45,000 to 50,000 barrels of oil per day
  • Substantially all of 2016 estimated oil production volumes hedged at an average price of approximately $80 per barrel of oil
  • Expecting full year average well costs to be approximately 10 to 15 percent lower than 2015

1 Based on the average first day  of the month spot price for the preceding 12-month period of $50.28 per Bbl (WTI) and $2.59 per MMBtu (Henry Hub).

"In 2015 our operations team executed well and improved our asset quality in a very challenging macro environment," said Brent Smolik, chairman, president and chief executive officer of EP Energy Corporation. "We increased efficiencies, lowered costs and improved well performance in all of our drilling and completion programs. Throughout the year we remained focused on capital discipline, maintained our future drilling inventory, improved our financial flexibility and generated free cash flow in the second half of 2015, as expected."

2015 Financial Results

Fourth Quarter 2015

For the quarter ended December 31, 2015, EP Energy reported $0.22 Adjusted EPS and $1.42 Discretionary Cash Flow Per Share.  Adjusted EBITDAX for the fourth quarter 2015 was $425 million, up from $406 million in the fourth quarter of 2014 due to lower lifting costs, lower adjusted G&A costs, and lower production taxes primarily related to lower commodity prices.

The company ended the year with fourth quarter adjusted cash operating costs of $8.87 per Boe, well below the company's annual estimates.

In addition, the company recorded a non-cash impairment charge with respect to the fourth quarter of 2015 of approximately $4.3 billion on certain oil and gas properties located primarily in its Eagle Ford program, attributable primarily to a significant decline in commodity prices.

Full Year 2015

For the year ended December 31, 2015, EP Energy reported $0.78 Adjusted EPS and $5.46 Discretionary Cash Flow Per Share.  Adjusted EBITDAX for the year 2015 was $1,641 million, up from $1,547 million in 2014 due primarily to higher production volumes, higher hedge settlements, lower lifting costs, lower adjusted G&A costs, and lower production taxes primarily related to lower commodity prices.

Total adjusted cash operating costs for the year ended December 31, 2015 was $9.89 per Boe, which was below full year company estimates for 2015. 

2015 capital expenditures were $1.2 billion, before Eagle Ford acquisition capital of $112 million.  EP Energy focused investments in its core programs, spending $743 million, $249 million, $158 million, and $60 million in Eagle Ford, Wolfcamp, Altamont, and Haynesville, respectively.

Note: Data throughout this release has been adjusted to exclude completed domestic and international asset sales prior to December 31, 2014.  See Disclosure of Non-GAAP Financial Measures section of this release for applicable definitions and reconciliations to GAAP terms.

Operations

For the year ended December 31, 2015, average daily production was 109.7 MBoe/d, including 60.5 MBbls/d of oil.  Production volumes increased throughout the year and fourth quarter 2015 average daily production was 112.6 MBoe/d, including 56.5 MBbls/d of oil.

During the fourth quarter of 2015, the company reduced its completion activity due to the lower commodity price environment, and grew its completion backlog which provides increased efficiency and operational flexibility in the future.

Eagle Ford Program

In 2015, the company completed 118 wells in its Eagle Ford program and grew production to 58.2 MBoe/d, a 14 percent increase compared with 2014.  During the fourth quarter 2015, the company completed 14 wells and produced 56.2 MBoe/d, a 3 percent increase from the fourth quarter of 2014.

EP Energy continued to reduce well costs in its Eagle Ford program. The average 2015 well cost was approximately $5.8 million, almost 20 percent lower than 2014 average well cost of $7.2 million, despite drilling longer laterals with more frac stages per well in 2015.

The company improved efficiencies by drilling multi-well pads and optimizing well and completion designs.  EP Energy continues to evolve its development design and lateral placement, testing staggered landing zones to reduce frac interference. The company is encouraged by initial results from wells drilled with the new design.

In its Eagle Ford program, EP Energy successfully completed its asset acquisition in the third quarter, adding 197 future drilling locations. During the fourth quarter, the company successfully integrated these properties and wells into its current operations.

Wolfcamp Program

In 2015, the company completed 36 wells in its Wolfcamp program and produced 19.9 MBoe/d, a 30 percent increase from 2014. In the fourth quarter of 2015, the company completed one well late in the quarter and produced 21.2 MBoe/d, a 23 percent increase from the fourth quarter of 2014. 

Total well costs in the Wolfcamp program averaged $5.3 million in 2015 which was approximately 15 percent lower than 2014 average well costs of $6.2 million. This cost reduction was realized even as the company applied enhanced completion designs with more proppant and a greater number of stages per well in 2015. The improved completion designs resulted in better well performance.  Average initial 30-day production rates in 2015 were 528 BOPD, which was 68 percent higher than 315 BOPD in 2014.

Altamont Program

The company continued to efficiently develop its Altamont program with lower well costs and improved well results. In 2015, the company completed 30 wells and continued to grow production with full year volumes of 17.1 MBoe/d, 10 percent higher than 2014.  In the fourth quarter 2015, the company completed two wells and had production volumes of 16.3 MBoe/d.

The company continued to reduce well costs in its Altamont program with an average cost of $4.1 million in 2015 which was approximately 21 percent below the 2014 average well cost of $5.2 million.

During the fourth quarter of 2015, the company reduced operating expense and increased focus on its base production and recompletion program. The company is also benefiting from improved realized pricing relative to WTI oil prices.

EP Energy recently entered into a drilling partnership in Altamont with a 12-well program, which the company will operate. The transaction is expected to significantly increase well-level returns due to a capital carry. The company will begin drilling partnership wells in the first half of 2016.

Haynesville Program

In 2015, EP Energy drilled its first new Haynesville wells since 2012 utilizing a new drilling and completion design, which included tighter stage spacing and increased proppant loadings. The company completed two wells with 4,500 foot laterals and two wells with 7,500 foot laterals.

Production from the new wells contributed to increased fourth quarter natural gas volumes which were 113 MMcf/d in 2015 compared with 85 MMcf/d for the same 2014 period. For the full year 2015, volumes were 87 MMcf/d compared with 96 MMcf/d for 2014.

Hedge Program Update

In 2015 EP Energy realized $942 million from settlements on financial derivatives. At year-end 2015, the MTM value of the company's hedge positions was approximately $800 million. EP Energy has effectively hedged all of its expected oil production for 2016 at an average price of approximately $80 per barrel.

A summary of the company's 2016 and 2017 hedge positions is listed below:

2016

2017

Total Fixed Price Hedges

Oil volumes (MMBbls)

18.0

5.1

Average floor price ($/Bbl)

$

80.29

$

65.87

Natural gas volumes (TBtu)

7.3

Average floor prices ($/MMBtu)

$

4.20

$

 

Note:  Positions are as of December 31, 2015 (Contract months: January 2016 - Forward) and the table includes 2017 WTI three-way collars of 1.1 MMBbls.

Financial Position and Liquidity

At December 31, 2015, EP Energy's balance sheet included approximately $26 million of cash and cash equivalents and $4.8 billion of total net debt. 

The company maintains a significant liquidity position of $1.6 billion at year-end 2015. EP Energy has a $2.75 billion reserve-based loan facility which is supported by the company's proved reserve base. The company has no near-term debt maturities with its first significant maturity due in 2018.

2015 Proved Reserves

EP Energy's proved oil and natural gas reserves were 546.0 MMBoe as of December 31, 2015, a 12 percent decrease compared to proved reserves at December 31, 2014 of 622.2 MMBoe. Proved reserves in 2015 were 44 percent proved developed producing and 55 percent oil.

2015 proved reserves were lower than 2014 due to lower prices and the impact of the SEC's five-year development rule after our reduction in estimated capital in the company's long-range development plan based on the lower price environment.

The company operates 86 percent of its producing wells and has operational control over approximately 97 percent of its drilling inventory as of December 31, 2015.

The first day 12-month average SEC prices for reserves as of December 31, 2015 were $50.28 per Bbl for oil, $2.59 per MMBtu for gas and $16.64 per Bbl for NGL. These prices were higher than prices on December 31, 2015, which were $37.04 per Bbl for oil and $2.34 per MMBtu for natural gas.

The company's pre-tax PV-10 was approximately $2.0 billion compared with year-end 2014 reported  PV-10 of approximately $9.4 billion. The lower PV-10 in 2015 is primarily the result of substantially lower commodity prices and the impact on reserves of the SEC's five-year development rule after our reduction in estimated capital in the company's long-range development plan based on the lower price environment.

Future Drilling Inventory

At year-end 2015, EP Energy's estimated future drilling inventory, which includes proved undeveloped reserves and unproven resources, included 5,709 identified future drilling locations with 973 in Eagle Ford, 3,264 in Wolfcamp, 1,282 in Altamont and 190 in Haynesville.

YE 2014

2015 Drilling

Program

Acquisitions

Net

Additions

YE 2015

Eagle Ford

872

(118)

197

22

973

Wolfcamp

3,300

(36)

3,264

Altamont

1,304

(30)

8

1,282

Haynesville

197

(4)

(3)

190

Total

5,673

(188)

197

27

5,709

 

2016 Outlook

"Entering 2016 we face many of the same macro challenges of 2015. In response, our 2016 outlook includes significantly lower capital spending, reduced activities and lower costs," added Mr. Smolik. "During the year, we expect to improve our financial strength while maintaining operational advantages. Our primary objectives are to remain free cash flow positive, improve the balance sheet and allocate capital to projects which add the most value. We have line of sight to generate free cash flow this year as our 2016 oil production is effectively hedged at $80 per barrel, we have significant capital funding flexibility and our cost structure continues to improve."

2016 Capital Program

EP Energy maintains significant flexibility with regard to the allocation and timing of its capital budget. The company's 2016 capital spend is expected to be $500 million to $900 million.

Equivalent production in 2016 is expected to be 91 MBoe/d to 97 MBoe/d with 45 MBbls/d to 50 MBbls/d of oil production. The pace and timing of capital activities will impact production levels.  The company expects activity levels in the first half of 2016 to be consistent with the low end of guidance ranges. Activity levels can be increased in the second half of the year if commodity prices recover.

At the mid-point, year-over-year capital spending is expected to be down approximately 45 to 50 percent and the company expects to generate free cash flow in 2016.

Efficient Operating Costs

EP Energy maintains efficient operations and continues to significantly lower cash costs which were below guidance ranges in 2015.  In 2016 the company expects to focus on maintaining an efficient cost structure with adjusted cash operating costs of $9.50 to $10.50 per Boe and transportation costs of $3.40 to $3.65 per Boe.

Operations

For the full year the company expects to complete 75 to 160 wells.

EP Energy will focus the majority of its activity in its Eagle Ford program, which generates the highest returns in the company.  In the first half of 2016 the company will focus on its most efficient areas of the Eagle Ford while maintaining lease commitments with a one-rig program.  Average well cost in 2016 is expected to be $4.8 million compared with an average well cost of $5.8 million in 2015.

In its Wolfcamp program, the company expects to expand its technical knowledge and broaden its development area.  In 2016, EP Energy plans more activity in Reagan County including A-bench tests and longer laterals across its acreage. Average well cost in 2016 is expected to be $4.4 million compared with an average well cost of $5.3 million in 2015.

In its Altamont program, the company expects to be active in its new drilling partnership and its capital efficient recompletion program. EP Energy is focused on optimizing its base production while continuing to lower costs. Average well cost in 2016 is expected to be $4.2 million compared with an average well cost of $4.1 million in 2015. The slight increase in cost is due to deeper average well depths in 2016.

In its Haynesville program, the company updated its drilling and completion designs in 2015.  In 2016, the company is focused on enhancing its base production and optimizing operating costs while it reviews the commodity price environment for natural gas relative to oil in determining future activity levels.

The table below summarizes the company's operational and financial guidance for 2016 compared with 2015 results.

2016

2015

Capital program ($ million)1

$500 – $900

$1,213

Production

Total production (MBoe/d)

91 – 97

109.7

Oil production (MBbls/d)

45 – 50

60.5

Completions

75 – 160

188

Adjusted cash operating costs (per Boe)

$9.50 – $10.50

$9.89

Transportation cost (per Boe)

$3.40 – $3.65

$2.88

1

2015 excludes approximately $111 million of acquisition capital.

Webcast Information

EP Energy has scheduled a webcast at 10 a.m. Eastern Time, 9 a.m. Central Time, on February 19, to discuss its fourth quarter and full year financial and operational results. The webcast may be accessed online through the company's website at epenergy.com in the Investor Center. Materials to be discussed during the webcast will be available in the Investor Center one hour prior to the webcast. A limited number of telephone lines will be available to participants by dialing 888-317-6003 (conference ID# 0434904) 10 minutes prior to the start of the webcast. A replay of the webcast will be available through March 21, 2016 on the company's website in the Investor Center (conference ID# 10079677).

About EP Energy

The EP Energy team has a passion for finding and producing the oil and natural gas that enriches people's lives. As a leading North American oil and natural gas producer, EP Energy has a proven strategy, a significant reserve base, multi-year drilling opportunities, and a strategic presence in fast-emerging unconventional resource areas. EP Energy is active in all phases of the E&P value chain—exploring for, acquiring, developing and producing oil and natural gas. For more information about EP Energy, visit epenergy.com.

Disclosure of Non-GAAP Financial Measures

The Securities and Exchange Commission's Regulation G applies to any public disclosure or release of material information that includes a non-GAAP financial measure. In the event of such a disclosure or release, Regulation G requires (i) the presentation of the most directly comparable financial measure calculated and presented in accordance with GAAP and (ii) a reconciliation of the differences between the non-GAAP financial measure presented and the most directly comparable financial measure calculated and presented in accordance with GAAP.

Non-GAAP Terms

PV-10 is considered a non-GAAP measure derived from the standardized measure of discounted future net cash flows of our oil and natural gas properties, which is the most directly comparable GAAP financial measure. Our PV-10 differs from our standardized measure as the standardized measure reflects discounted future income taxes related to our operations. We believe that the presentation of PV-10 is useful to investors because it presents (i) relative monetary significance of our oil and natural gas properties regardless of tax structure and (ii) relative size and value of our reserves to other companies. We also use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10 and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil, natural gas and NGLs reserves.

Pricing used to calculate the company's PV-10 is based on SEC Regulation S-X, Rule 4-10 as amended, using the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month preceding the 12-month period prior to the end of the reporting period. The first day 12-month average price used to estimate our proved reserves at December 31, 2015 was $50.28 per barrel of oil (WTI) and $2.49 per MMBtu for natural gas (Henry Hub). The first day 12-month average U.S. price used to estimate our proved reserves at December 31, 2014 was $94.99 per barrel of oil (WTI) and $4.34 per MMBtu for natural gas (Henry Hub).

The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows:

12/31/15

12/31/14

($ millions)

PV-10

$

2,034

$

9,376

Income taxes, discounted at 10%

50

2,478

Standardized measure of discounted future net cash flows

$

1,984

$

6,898

 

EBITDAX is defined as income (loss) from continuing operations plus interest and debt expense, income taxes, depreciation, depletion and amortization and exploration expense. Adjusted EBITDAX is defined as EBITDAX, adjusted as applicable in the relevant periods, for the net change in the fair value of derivatives (mark-to-market effects of financial derivatives, net of  settlements and cash premiums paid or received related to these derivatives), the non-cash portion of compensation expense (which represents non-cash compensation expense under our long-term incentive programs adjusted for cash payments made under our long-term incentive plans), transition, restructuring and other non-recurring costs, management and other fees paid to the Sponsors, losses on extinguishment of debt and impairment charges.  Adjusted EBITDAX Margin Per Unit is calculated using Adjusted EBITDAX divided by consolidated equivalent volumes.

Below is a reconciliation of our EBITDAX and Adjusted EBITDAX to our consolidated net (loss) income:

Quarter ended

December 31,

Year ended

December 31,

2015

2014

2015

2014

($ in millions, except equivalent volumes and per unit)

Net (loss) income

$

(3,731)

$

634

$

(3,748)

$

731

Income from discontinued operations, net of tax

(1)

(4)

(Loss) income from continuing operations

(3,731)

633

(3,748)

727

Income tax (benefit) expense

(565)

365

(578)

432

Interest expense, net of capitalized interest

81

83

330

318

Depreciation, depletion and amortization

246

241

983

875

Exploration expense

6

4

18

22

EBITDAX

(3,963)

1,326

(2,995)

2,374

Mark-to-market on financial derivatives(1)

(209)

(1,029)

(667)

(985)

Settlements and cash premiums on financial derivatives(2)

293

104

942

44

Non-cash portion of compensation expense(3)

5

3

13

9

Transition, restructuring and other costs(4)

1

8

(4)

Fees paid to Sponsors(5)

90

Loss on extinguishment of debt(6)

41

17

Impairment charges

4,299

1

4,299

2

Adjusted EBITDAX(7)

$

425

$

406

$

1,641

$

1,547

Total equivalent volumes (MBoe)

10,362

9,417

40,033

35,673

Adjusted EBITDAX Margin Per Unit (MBoe)(8)

$

40.94

$

43.11

$

40.98

$

43.37

(1)

Represents the income statement impact of financial derivatives.

(2)

Represents actual settlements related to financial derivatives, including cash premiums. No cash premiums were received or paid for the quarters ended December 31, 2015 and 2014, or the year ended December 31, 2015. For the year ended December 31, 2014, we received approximately $1 million of cash premiums.

(3)

For both of the quarters ended December 31, 2015 and 2014, cash payments were less than $1 million.  For the years ended December 31, 2015 and 2014, cash payments were approximately $8 million and $13 million, respectively.

(4)

Reflects transition and severance costs related to restructuring for the year ended December 31, 2015. Reflects an $11 million insurance settlement and $5 million of acquisition costs as well as transition and severance costs related to restructuring or asset sales in 2015 and 2014.

(5)

Represents transaction, management and other fees paid to the Sponsors in 2014.

(6)

Represents the loss on extinguishment of debt recorded related to the repayment in May 2015 of our 2019 $750 million senior secured note for the year ended December 31, 2015. Represents the loss on extinguishment of debt recorded related to the retirement of the PIK toggle note in 2014, the redetermination of the RBL Facility and a partial repayment of the term loan in 2013.

(7)

The year ended December 31, 2014 does not include $11 million of Adjusted EBITDAX related to Arklatex and South Louisiana Wilcox classified as discontinued operations.

(8)

Adjusted EBITDAX Margin Per Unit is based on actual total amounts rather than the rounded totals presented.

Adjusted EPS is defined as diluted earnings per share adjusted for certain items that EP Energy considers to be significant to understanding our underlying performance for a given period. Adjusted EPS is useful in analyzing the Company's ongoing earnings potential and understanding certain significant items impacting the comparability of EP Energy's results. Adjusted EPS is income (loss) per common share from continuing operations adjusted for the impact of financial derivatives (mark-to-market effects of financial derivatives, net of settlements and cash premiums paid or received related to these derivatives), management and other fees paid to the Sponsors (which ended in 2014), losses on extinguishment of debt, impairment charges and other non-recurring costs, including valuation allowance on deferred tax assets.

Below is a reconciliation of Adjusted EPS to our consolidated diluted net loss per share:

Quarter ended December 31, 2015

Pre-Tax

After-Tax

Diluted EPS

($ in millions, except earnings per share amounts)

Net loss

$

(3,731)

$

(15.29)

Adjustments(1)

Impact of financial derivatives(2)

$

84

$

54

$

0.22

Impairment charges

4,299

2,755

11.29

Valuation allowance on deferred tax assets

975

4.00

Total adjustments

$

4,383

$

3,784

$

15.51

Adjusted EPS

$

0.22

Basic and fully diluted weighted average shares

244

Year ended December 31, 2015

Pre-Tax

After-Tax

Diluted EPS

($ in millions, except earnings per share amounts)

Net loss

$

(3,748)

$

(15.37)

Adjustments(1)

Impact of financial derivatives(2)

$

275

$

176

$

0.73

Loss on extinguishment of debt

41

26

0.11

Transition, restructuring and other costs(3)

8

5

0.02

Impairment charges

4,299

2,755

11.29

Valuation allowance on deferred tax assets

975

4.00

Total adjustments

$

4,623

$

3,937

$

16.15

Adjusted EPS

$

0.78

Basic and fully diluted weighted average shares

244

(1)

All individual adjustments assume a statutory federal and blended state tax rate, as well as any other income tax effects specifically attributable to that item.

(2)

Represents mark-to-market impact net of settlements and cash premiums related to financial derivatives.

(3)

Reflects transition and severance costs related to restructuring for the year ended December 31, 2015.

Cash operating costs is a non-GAAP measure calculated on a per Boe basis and includes total operating expenses less depreciation, depletion and amortization expense, transportation costs, exploration expense, oil and natural gas purchases, impairment charges and other expenses. Adjusted cash operating costs is a non-GAAP measure and is defined as cash operating costs less transition, restructuring and other non-recurring costs, management and other fees paid to the Sponsors (which terminated on January 23, 2014), and the non-cash portion of compensation expense (which represents compensation expense under our long-term incentive programs adjusted for cash payments made under our long-term incentive plans).

Below is a reconciliation of our cash operating costs and adjusted cash operating costs to our operating expenses:

Quarter Ended December 31,

2015

2014

Total

Per Unit(1)

Total

Per Unit(1)

($ in millions, except per unit costs)

Total operating expenses

$

4,688

$

452.39

$

399

$

42.33

Depreciation, depletion and amortization

(246)

(23.73)

(241)

(25.63)

Transportation costs

(34)

(3.19)

(29)

(3.06)

Exploration expense

(6)

(0.53)

(4)

(0.45)

Oil and natural gas purchases

(7)

(0.73)

(7)

(0.71)

Impairment charges

(4,299)

(414.84)

(1)

(0.12)

Total cash operating costs

96

9.37

117

12.36

Transition/restructuring costs, non-cash portion of compensation expense and other(2)

(5)

(0.50)

(3)

(0.36)

Total adjusted cash operating costs and adjusted per-unit cash costs

$

91

$

8.87

$

114

$

12.00

Total equivalent volumes (MBoe)

10,362

9,417

Year Ended December 31,

2015

2014

Total

Per Unit(1)

Total

Per Unit(1)

($ in millions, except per unit costs)

Total operating expenses

$

5,863

$

146.44

$

1,591

$

44.59

Depreciation, depletion and amortization

(983)

(24.54)

(875)

(24.53)

Transportation costs

(116)

(2.88)

(100)

(2.81)

Exploration expense

(18)

(0.44)

(22)

(0.62)

Oil and natural gas purchases

(31)

(0.79)

(23)

(0.64)

Impairment charges

(4,299)

(107.38)

(2)

(0.05)

Total cash operating costs

416

10.41

569

15.94

Transition/restructuring costs, non-cash portion of compensation expense and other(2)

(21)

(0.52)

(95)

(2.67)

Total adjusted cash operating costs and adjusted per-unit cash costs

$

395

$

9.89

$

474

$

13.27

Total equivalent volumes (MBoe)

40,033

35,673

(1)

Per unit costs are based on actual total amounts rather than the rounded totals presented.

(2)

For the quarter ended December 31, 2015, amount includes approximately $5 million of non-cash compensation expense. For the quarter ended December 31, 2014, amount includes $3 million of non-cash compensation expense adjusted for cash payments of less than $1 million and $1 million of restructuring charges.  For the year ended December 31, 2015, amount includes approximately $8 million of transition and severance costs related to restructuring and $13 million of non-cash compensation expense, adjusted for cash payments made of approximately $8 million. For the year ended December 31, 2014, amount includes $90 million of transaction, management and other fees paid to our Sponsors, $11 million of cash received from an insurance settlement, $5 million of acquisition costs, $9 million of non-cash compensation expense and $2 million of transition and severance costs related to restructuring.

 

The table below displays the average cash operating costs and adjusted cash operating costs per equivalent unit:

Quarter Ended December 31,

Year Ended December 31,

2015

2014

2015

2014

Average cash operating costs ($/Boe)

Lease operating expenses

$

4.53

$

5.39

$

4.64

$

5.40

Production taxes(1)

1.39

2.71

1.83

3.39

General and administrative expenses(2)

3.30

3.79

3.71

6.83

Taxes, other than production and income taxes

0.11

0.13

0.17

0.23

Other expense(3)

0.04

0.34

0.06

0.09

Total cash operating costs

9.37

12.36

10.41

15.94

Transition/restructuring costs, non-cash portion of compensation expense and other(2)

(0.50)

(0.36)

(0.52)

(2.67)

Total adjusted cash operating costs and adjusted per-unit cash costs(2)

$

8.87

12.00

$

9.89

13.27

(1)

Production taxes include ad valorem and severance taxes.

(2)

For additional detail of items included in general and administrative expenses, refer to the reconciliation of cash operating costs and adjusted cash operating costs above.

(3)

Includes early rig termination fees of $2 million and $3 million incurred during the years ended December 31, 2015 and 2014, respectively.

Discretionary Cash Flow and Discretionary Cash Flow Per Share are non-GAAP measures calculated using income (loss) from continuing operations adjusted for certain items including depreciation, depletion and amortization, the impact of financial derivatives (mark-to-market effects of financial derivatives, net of settlements and cash premiums paid or received related to these derivatives), transition, restructuring and other non-recurring costs, management and other fees paid to the Sponsors (which ended in 2014), deferred income taxes, non-cash exploration expense, and other non-cash income items.  The table below reconciles Discretionary Cash Flow to net cash provided by operating activities under GAAP.

Below is a reconciliation of Discretionary Cash Flow to our consolidated net (loss) income and operating cash flow:

Quarter ended

December 31, 2015

Year ended

December 31, 2015

Net loss

$

(3,731)

$

(3,748)

Depreciation, depletion and amortization

246

983

Impact of financial derivatives (1)

84

275

Transition, restructuring and other costs (2)

8

Deferred income taxes

(564)

(578)

Non-cash exploration expense

4

14

Impairment charges

4,299

4,299

Other non-cash income items

9

78

Discretionary Cash Flow

$

347

$

1,331

Discretionary Cash Flow Per Share (3)

$

1.42

$

5.46

Discretionary Cash Flow

$

347

$

1,331

Transition, restructuring and other costs (2)

(8)

Working capital and other changes

(59)

4

Net cash provided by operating activities

$

288

$

1,327

(1)

Represents mark-to-market impact net off settlements and cash premiums related to financial derivatives.

(2)

Reflects transition and severance costs related to restructuring for the quarter and year ended December 31, 2015.

(3)

Reflects basic and fully diluted weighted average shares of approximately 244 million for both the quarter and year ended December 31, 2015. 

Net Debt is a non-GAAP measure defined as long-term debt less cash and cash equivalents. We believe Net Debt provides useful information to investors for analysis of the Company's financial position and/or liquidity. In addition, the company believes that these measures are widely used by professional research analysts and others in the valuation, comparison and investment recommendations of companies in the oil and gas exploration and production industry.

We believe that the presentation of Adjusted EPS, EBITDAX, Adjusted EBITDAX and Adjusted EBITDAX Margin Per Unit, is important to provide management and investors with additional information (i) to evaluate our ability to service debt adjusting for items required or permitted in calculating covenant compliance under our debt agreements, (ii) to provide an important supplemental indicator of the operational performance of our business, (iii) for evaluating our performance relative to our peers, (iv) to measure our liquidity (before cash capital requirements and working capital needs) and (v) to provide supplemental information about certain material non-cash and/or other items that may not continue at the same level in the future.   We believe that the presentation of Discretionary Cash Flow and Discretionary Cash Flow Per Share is important because it provides management and investors with useful additional information for analysis of the company's ability to internally generate funds for exploration, development and acquisitions as well as adjusting net income (loss) for unusual items to allow for a more consistent comparison from period to period. We believe that the presentation of Cash Operating Costs and Adjusted Cash Operating Costs per unit provides management and investors valuable measures of operating performance and efficiency.

Adjusted EPS, EBITDAX, Adjusted EBITDAX, Adjusted EBITDAX Margin Per Unit, Discretionary Cash Flow, Discretionary Cash Flow Per Share, Cash Operating Costs, Adjusted Cash Operating Costs and Net Debt have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under U.S. GAAP or as an alternative to net income (loss), income (loss) from continuing operations, operating income (loss), earnings (loss) per share, operating expenses, operating cash flows or other measures of financial performance or liquidity presented in accordance with GAAP. For example, our presentation of Adjusted EPS, EBITDAX, Adjusted EBITDAX, Adjusted EBITDAX Margin Per Unit, Discretionary Cash Flow, Discretionary Cash Flow Per Share, Cash Operating Costs, Adjusted Cash Operating Costs and Net Debt may not be comparable to similarly titled measures used by other companies in our industry. Furthermore, our presentation of Adjusted EPS, EBITDAX, Adjusted EBITDAX, Adjusted EBITDAX Margin Per Unit, Discretionary Cash Flow, Discretionary Cash Flow Per Share, Cash Operating Costs, Adjusted Cash Operating Costs and Net Debt should not be construed as an inference that our future results will be unaffected by the items noted above or what we believe to be other unusual or non-recurring items or that in the future we may not incur expenses that are the same as or similar to some of the adjustments in this presentation.

Cautionary Statement Regarding Forward-Looking Statements

This release includes certain forward-looking statements and projections of EP Energy. We have made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors could cause actual results to differ materially from the projections, anticipated results or other expectations expressed, including, without limitation, the supply and demand for oil, natural gas and NGLs; the company's ability to meet production volume targets; changes in commodity prices and basis differentials for oil and natural gas; the uncertainty of estimating proved reserves and unproved resources; the future level of service and capital costs; the availability and cost of financing to fund future exploration and production operations; the success of drilling programs with regard to proved undeveloped reserves and unproved resources; the company's ability to comply with the covenants in various financing documents; the company's ability to obtain necessary governmental approvals for proposed E&P projects and to successfully construct and operate such projects; actions by the credit rating agencies; credit and performance risk of our lenders, trading counterparties, customers, vendors and suppliers; general economic and weather conditions in geographic regions or markets served by the company, or where operations of the company are located, including the risk of a global recession and negative impact on oil and natural gas demand; the uncertainties associated with governmental regulation, including any potential changes in federal and state tax laws and regulations; competition; and other factors described in the company's Securities and Exchange Commission filings. While the company makes these statements and projections in good faith, neither the company nor its management can guarantee that anticipated future results will be achieved. Reference must be made to those filings for additional important factors that may affect actual results. EP Energy assumes no obligation to publicly update or revise any forward-looking statements made herein or any other forward-looking statements made by EP Energy, whether as a result of new information, future events, or otherwise.

Contact Investor and Media Relations Bill Baerg 713-997-2906 bill.baerg@epenergy.com

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SOURCE EP Energy Corporation



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